There are many oil recovery processes of the prior art employed for the production of oil from subterranean reservoirs. Some of these use vertical wells or combine vertical and horizontal wells. Examples of pattern processes are the inverted 7-spot well pattern that has been employed for steam, solvent and combustion-based processes using vertical wells, and the staggered horizontal well pattern of U.S. Pat. No. 5,273,111 which has been employed (but limited to) a process using steam injection.
U.S. Pat. No. 5,626,191 discloses a repetitive method [now termed Toe-to-Heel Air Injection (THAI)] whereby the vertical segment of a vertical-horizontal producer well is subsequently converted to an air injection well, to assist in mobilizing oil for recovery by an adjacent horizontal well, which is subsequently likewise converted into an air injection well, and the process repeated.
U.S. Pat. No. 6,167,966 employs a water-flooding process employing a combination of vertical and horizontal wells.
U.S. Pat. No. 4,598,770 (Shu et al, 1986) discloses a steam-drive pattern process wherein alternating horizontal injection wells and horizontal production wells are all placed low in a reservoir. In situ combustion processes are not contemplated.
Joshi in Joshi, S. D., “A Review of Thermal oil Recovery Using Horizontal wells”, In Situ, 11(2 &3), 211-259 (1987), discloses a steam-based oil recovery process using staggered and vertically-displaced horizontal injection and production wells pattern. A major concern is the high heat loss to the cap rock when steam is injected at the top of the reservoir.
U.S. Pat. No. 5,273,111 (Brannan et al, 1993) teaches a steam-based pattern process for the recovery of mobile oil in a petroleum reservoir. A pattern of parallel offset horizontal wells are employed with steam injectors. The horizontal sections of the injection wells are placed in the reservoir above the horizontal sections of the production wells, with a horizontal production well drilled into the reservoir at a point below the injection wells, but intermediate said injection wells. Steam is injected on a continuous basis through the upper injection wells, while oil is produced through the lower production wells. Neither in situ combustion nor line drive processes are taught.
U.S. Pat. No. 5,803,171 (McCaffery et al, 1998) teaches an improvement of the Brennan patent wherein cyclic steam stimulation is used to achieve communication between the injector and producer prior to the application of continuous steam injection. In situ combustion processes are not mentioned.
U.S. Pat. No. 7,717,175 (Chung et al, 2010) discloses a solvent-based process utilizing horizontal well patterns where parallel wells are placed alternately higher and lower in a reservoir with the upper wells used for production of solvent-thinned oil and the lower wells for solvent injection. Gravity-induced oil-solvent mixing is induced by the counter-current flow of oil and solvent. The wells are provided with flow control devices to achieve uniform injection and production profiles along the wellbores. The devices compensate for pressure drop along the wellbores which can cause non-uniform distribution of fluids within the wellbore and reduce reservoir sweep efficiency. In situ combustion processes are not mentioned.
WO/2009/090477 (Xia et al) discloses an in situ combustion pattern process wherein a series of vertical wells that are completed at the top are placed between horizontal producing wells that are specifically above an aquifer. This arrangement of wells is claimed to be utilizable for oil production in the presence of an aquifer.
US Patent Application 2010/0326656 (Menard, 2010) discloses a steam pattern process entailing the use of alternating horizontal injection and production wells wherein isolated zones of fluid egress and ingress are created along the respective wellbores in order to achieve homogeneous reservoir sweep. The alternating wellbores may be in the same vertical plane or alternating between low and high in the reservoir, as in U.S. Pat. No. 5,803,171. Hot vapour is injected in the upper wells (e.g. steam).
Canadian Patent Application 2,698,454 (Ayasse) teaches a combustion process in which a horizontal oxidizing gas injection well is placed high in the reservoir directly above an oil producing horizontal well placed low in the reservoir. After ignition, the combustion front grows laterally from the injector with oil and combustion gas draining into the lower producing well placed low in the reservoir. The overall field development is by the sequential placement of injector-producer well pairs in a pattern.
As seen from the above patents, steam-based oil recovery processes are commonly employed to recover heavy oil and bitumen from underground formations. For example, steam-assisted-gravity-drainage (SAGD) and cyclic steam injection are used for the recovery of heavy oil and cold bitumen. When the oil is mobile as native oil or is rendered mobile by some in situ pre-treatment, such as a steam drive process, the thus-mobilized oil can then drain downwardly by gravity and be collected by a horizontal collector well.
A serious drawback of steam drive processes is the inefficiency of generating steam at the surface because a considerable amount of the heat generated by the fuel is lost without providing useful heat in the reservoir. Roger Butler, in his book “Thermal Recovery of oil and Bitumen’, p. 415, 416, estimates the thermal efficiency at each stage of the steam-injection process as follows: steam generator, 75-85%; transmission to the well, 75-95%' flow down the well to the reservoir, 80-95%; flow in the reservoir to the condensation front, 25-75%. It is necessary to keep the reservoir between the injector and the advancing condensation front at steam temperature so that the major energy transfer can occur from steam condensing at the oil face. In conclusion, 50% or more of the fuel energy can be lost before heat arrives at the oil face. The energy costs based on BTU in the reservoir are 2.6-4.4 times lower for air injection compared with steam injection. Several other drawbacks occur with steam-based oil recovery processes: natural gas may not be available to fire the steam boilers, fresh water may be scarce and clean-up of produced water for recycling to the boilers is expensive. In summary, steam-based oil recovery processes are thermally inefficient, expensive and environmentally unfriendly.
Improved efficiency, shortened time on initial return on investment (ie quicker initial oil recovery rates to allow more immediate return on capital invested), and decreased initial capital cost, in various degrees, are each areas in the above methods which may be improved.